Method And Apparatus For Hydraulic Fracturing And Monitoring

ABSTRACT

A technique that is usable with a well includes deploying an assembly into a wellbore. The assembly includes at least one sensor. A fracturing fluid is injected under pressure into the wellbore to hydraulically fracture a subterranean formation of interest. The technique includes isolating the sensor from the fracturing and measuring acoustical energy that is generated by the hydraulic fracturing using the sensor(s).

This application claims the benefit under 35 U.S.C. § 119(e) to U.S.Provisional Patent Application Ser. No. 60/782,161, entitled, “METHODAND APPARATUS FOR HYDRAULIC FRACTURING AND MONITORING,” which was filedon Mar. 14, 2006, and is hereby incorporated by reference in itsentirety.

BACKGROUND

The subject matter of the present invention relates to a method andapparatus for hydraulic fracturing and monitoring.

Hydraulic fracturing is used to increase conductivity of a subterraneanformation for recovery or production of hydrocarbons and to permitinjection of fluids into subterranean formation or into injection wells.In a typical hydraulic fracturing operation, a fracturing fluid isinjected under pressure into the formation through a wellbore.Particulate material known as proppant may be added to the fracturingfluid and deposited in the fracture as it is formed to hold open thefracture after hydraulic fracturing pressure is relaxed.

As the hydraulic fracturing fluid is delivered from the surface to thesubterranean formation through the wellbore, it is important that thepressured fluid for fracturing be directed into the formation orformations of interest. Typically, the subterranean formation orformations are hydraulically fractured through either perforations in acased well bore or in an isolated section of the open well bore. Oneimportant consideration for fracturing for hydrocarbon production orwaste disposal is directing the fracture into a desired formation. Theorientation of the hydraulic fracture is controlled by formationcharacteristics and the stress regime in the formation. It is importantto monitor the fracture as it is being formed to insure that it does notextend beyond the intended zone and has the desired extent andorientation.

It is known that hydraulic fracturing operations in a wellbore generatesignificant seismic activity as a result of the fracture growth into asubterranean formation. Fluid injected under pressure into asubterranean formation causes a pressure build up until the in-situstress in a subterranean formation is exceeded, resulting in fracturesin the formation that extend some distance from the wellbore. Thisformation fracturing creates a series of small “micro-earthquakes” knownas microseisms. These discrete, localized microseisms occur during thegrowth of fractures, and the amplitude of the seismic or acousticalenergy (compressional (“P”) waves and shear (“S”) waves) are generatedwith significant enough amplitude to be detected by remote sensors.Accordingly, by sensing and recording the P and S waves and theirrespective arrival times at each of the sensors, the acoustical signalscan be processed in accordance with known seismic or earthquakemonitoring methodology to determine the position of the microseisms.Hence, the geometry of the fracture and its location may be inferred.One method for determining the orientation of fractures resulting fromhydraulic fracturing operations is described in U.S. Pat. No. 6,985,816,incorporated herein by reference.

One method known for monitoring the location and size of a hydraulicfracture is called microseismic mapping. In this method, a second offsetwell is used for monitoring hydraulic fracturing activities in theprimary treatment or injection well. In microseismic mapping, aplurality of acoustic sensors (e.g., geophones) are positioned in a welloffset from the well to be fractured. These sensors in the offset wellare used to record signals that result from microseisms caused by thestress induced in the subterranean surface formations by the hydraulicfracture fluid pressure build-up in the treatment or injection well.

Examples of microseismic monitoring are described in U.S. Pat. No.5,771,170 by Withers, et al. and U.S. Pat. No. 5,996,726 by Sorrels andWarpinski. In the methods therein, location of fractures within aninjection well are monitored in separate instrumented monitoring wellsusing acoustic signals resulting from microseismic events caused by thefracturing activity in the injection well. Separate dedicated monitoringwells however add significant expense to these methods. Limited effortshave been made to use devices deployed in injection or treatment wellsfor microseismic monitoring in treatment or injection wells. In U.S.Pat. No. 6,935,424, a method for mitigating risk of adversely affectinghydrocarbon productivity (e.g. screen out) during fracturing bymonitoring the fracturing process is described. The method usestiltmeters coupled to the casing or borehole wall in the well undergoinghydraulic fracturing to mechanically measure deformation, thedeformation measurement being used to infer fracture dimensions. In thismethod however less than desirable coupling of the tiltmeters to thecasing or borehole wall significantly impacts the accuracy of theinferred dimensions. In U.S. Pat. No. 5,503,225 acoustic sensors aredeployed in an injection well for microseismic monitoring. The sensorsare isolated in the annulus of the waste injection well, with thesensors generally being attached to the tubing string. In such aconfiguration however the acoustic noise in the downhole tubing causedby the fluid injection will be sensed by such a system and likely willsignificantly mask any sensed microseismic events. While these methodseliminate the need and expensive of the dedicated monitoring wells, thelimitations of each preclude their use to accurately distinguishmicroseismic events.

Thus, there is a continuing need for better ways to reliably andaccurately monitor hydraulic fracturing and injection operations.

SUMMARY

In an embodiment of the invention, a technique that is usable with awell includes deploying an assembly into a wellbore. The assemblyincludes at least one sensor. A fracturing fluid is injected underpressure into the wellbore to hydraulically fracture a subterraneanformation of interest. The technique includes measuring acousticalenergy that is generated by the hydraulic fracturing using thesensor(s).

In another embodiment of the invention, an apparatus for use in a wellincludes an assembly that has a tool body with at least one acousticenergy sensor that is disposed thereon. The assembly also includes anisolation device to isolate the acoustic energy sensor from a hydraulicfracture operation.

Advantages and other features of the invention will become apparent fromthe following drawing, description and claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a well according to an embodiment of the invention.

FIG. 2 is a schematic diagram of a sensor sonde according to anembodiment of the invention.

FIG. 3 is a flow diagram depicting a technique to monitor acousticalenergy that is generated by hydraulic fracturing according to anembodiment of the invention.

FIG. 4 is a flow diagram depicting a technique to perform hydraulicfracturing in different zones of a well and monitor the fracturingaccording to an embodiment of the invention.

FIG. 5 is a flow diagram depicting a technique to monitor acousticalenergy that is generated by hydraulic fracturing according to anembodiment of the invention.

DETAILED DESCRIPTION

Referring to FIG. 1, in accordance with an embodiment of the invention,a well 8 includes acoustic energy sensors 160 that are located downholefor purposes of monitoring the acoustical energy that is generated byhydraulic fracturing. Sensors 160 may be isolated from a formation ofinterest 60 in which hydraulic fracturing occurs. Due to the isolation,flow noise attributable to the fracturing operation does not affect themeasurements by the sensors 160, and furthermore, the sensors 160 areprotected from the impact of the fracture treatment.

In accordance with some embodiments of the invention, the sensors 160are part of sensor sondes 120 (sensor sondes 120 ₁, 120 ₂ and 120 ₃,being depicted as examples in FIG. 1) of a borehole monitoring assembly10 of a downhole borehole assembly 100. In addition to the boreholemonitoring assembly 10, the borehole assembly 100 optionally includes anisolation device, such as a isolation device 50 (a compression-setpacker, a mechanically-set packer, a hydraulically-set packer, aweight-set packer, swellable bladder, plug, etc., as just a fewexamples), for purposes of isolating the sensor sondes 120 (and thus,the sensors 160) from the fracturing operation.

The borehole assembly 100 may be run into the well 8 using one of manyconveyance mechanisms, such as a tubular string 30 that is depicted inFIG. 1. As a more specific example, the string 30 may be coiled tubing.

In general, a surface acquisition system 80 may be in communication withthe borehole monitoring assembly 100 via a communication line 40, suchas a wireline, slickline, fiber optics or a fiber optics tether. Fiberoptic tether refers to fiber optics deployed within a protective coveror small diameter protective tubing. One example of a data receiving andprocessing system that may serve as the surface acquisition system 80 isdescribed in U.S. Pat. No. 6,552,665, which is incorporated herein inits entirety. The communication line 40 may be contained or deployed inthe string 30 to provide communication from the surface control systemto the borehole monitoring assembly 100 or communication from theborehole monitoring assembly 100 to the surface control system or both.Communication and/or power may be provided by the communication lines40, depending on the particular embodiment of the invention.

The borehole monitoring assembly 10 may be any assembly or tool, whichis suited to monitor acoustic signals in a wellbore. In accordance withsome embodiments of the invention, each sonde 120 of the boreholemonitoring assembly 10 may be a similar sensor to the sonde that isdescribed in U.S. Pat. No. 6,170,601, which is hereby incorporated byreference in its entirety.

FIG. 2 depicts an exemplary embodiment of the sonde 120 in accordancewith some embodiments of the invention. In general, the sonde 120includes a tool body 124, which has a cavity 130 in an opening in thewall of the tool body 124. The cavity 124 receives an acoustic energysensor package 140, which is positioned in the cavity 130 and is mountedon resilient mounts 150 (springs, for example) to press the acousticsensor package 140 against the borehole wall (or casing string 22, ifthe well is cased), yet isolate the sensors 160 of the package 16 fromfluid-conveyed pressure disturbances. The sonde 120 may include three ofthe sensors 160, each of which senses acoustic energy along a differentaxis (x, y or z axis). Referring to FIG. 2 in conjunction with FIG. 1,the sonde 120 may also include an arm 136 that is activated to press thesonde 120 against the borehole wall (or casing string 22, if the well 10is cased) for purposes of placing the sensors 160 in proximity to thewellbore or casing string 22.

Referring back to FIG. 1, as noted above, the well 8 may be cased (viathe casing string 22) or uncased, depending on the particular embodimentof the invention. If installed, the casing string 22 may extend from thesurface along the entire length of a wellbore 20, or only along aportion of the wellbore 20. Furthermore, in accordance with otherembodiments of the invention, the wellbore 20 in which the boreholeassembly 100 is deployed may be a deviated or lateral wellbore. In someembodiments in a deviated or lateral wellbore, a tractor may be used todeploy the borehole assembly 100. Furthermore, the well 10 may be asubterranean or a subsea well, depending on the particular embodiment ofthe invention. Thus, many variations are possible and are within thescope of the appended claims.

In the state of the well that is depicted in FIG. 1, the well 8 has beenperforated in a previous trip by a perforating gun to form correspondingperforations in the casing string 22 and corresponding perforationtunnels 61, which extend into the formation of interest 60.

The borehole assembly 100 is deployed in the well 8 for purposes ofhydraulic fracturing and monitoring of the fracturing. Such hydraulicfracturing may be desired or performed for a variety of purposes, suchas but not limited to increasing or improving hydrocarbon recovery fromthe formation of interest 60 or injecting fluid, such as water, producedwater, enhanced oil recovery fluids, or gas into formation of interest60. The term fracturing fluid as used herein includes any fluid injectedfor the purposes of fracturing the formation and includes but is notlimited to treatment fluids, enhanced recovery fluids, and disposalfluids. There is shown in FIG. 1 only one subterranean formation ofinterest 60 for the purposes of illustration. It is contemplated thatthere may be multiple subterranean formations of interest 60 in anywellbore 20; and these multiple formations may be hydraulicallyfractured separately, together, or in various combinations as theoperator so desires.

Isolation device 50 is also deployed into the wellbore on a string 30,as part of the borehole assembly 100. More specifically, the isolationdevice 50 may be positioned along the string 30 above the boreholemonitoring assembly 10.

The sensors 160 form an array of sensors and may be selected from anyappropriate sensing devices such as geophones, hydrophones, oraccelerometers, and various combinations that generate signals inresponse to received acoustic energy. Any one type of acoustic energysensor or a combination of types may be used. The acoustic energy sensoror sensors should have good sensitivity to acoustic energy in themicroseismic frequency band greater than 30 Hz. This band may extend ashigh as 4 kiloHertz (kHz), as an example.

More than one acoustic energy sensor may be used in combination withother acoustic sensors to form an acoustic energy sensor package.Embodiments may comprise a plurality of tri-axial (3 orthogonal)geophones to provide sensing capabilities in three directions. Suchacoustic sensor packages may be spaced at desired intervals (e.g. 50 ft)along the wellbore 20. Acoustic sensor packages may be coupled to thewellbore wall or casing 22 via an anchoring system for borehole seismictools.

The signals that are generated by each of the sensors 160 in response toacoustical energy are digitized and transmitted through thecommunication line 40 to the surface acquisition system 80, at thesurface of the well 8. The sensors 160 may provide a digital or opticalsignal directly to the communication line 40 or a converter may be usedto convert the acoustic signals received by the sensors to digital oroptical signals for transmission. In some embodiments, the surfaceacquisition system 80 may employ methods, such as digital filters, toremove noise from the hydraulic fracturing pumping operations from thegenerated signals. In some embodiments, the signals generated by eachsensor are recorded in one or more memory devices that may be part ofthe borehole monitoring assembly 10, the memory devices generally beingrecoverable with the bottomhole monitoring assembly 10. In suchembodiments using memory devices, the signals may also be transmittedvia the communication line 40, while in other embodiments the signalsare not also transmitted via a communication line, as the sensor datathat is stored in the memory devices may be retrieved after the boreholeassembly 100 is retrieved from the well.

As depicted in FIG. 1, the borehole monitoring assembly 10 and theacoustic energy sensors 160 thereof are positioned in the wellbore at alocation that is not adjacent to the formation of interest 60. Theborehole monitoring assembly 10 may be positioned below the formation ofinterest 60. In the event that the wellbore is cased, boreholemonitoring assembly 10 may be positioned in the wellbore in a locationthat it not adjacent to the perforated zone in the casing. The boreholemonitoring assembly 10 may be placed below the perforated zone and thus,as depicted in FIG. 1, the sondes 120 may be suspend from a cable from atubular body that is mounted to the isolation device 50 and forms thelower end of the string 30. The isolation device 50 is deployed in thewellbore 20 to separate the borehole monitoring assembly 10 from thesubterranean formation of interest 60. In this manner, the boreholemonitoring assembly 10 is isolated from hydraulic fracturing orinjection activity undertaken in subterranean formation of interest 60.

In some embodiments of the invention, a noise suppression device ordevices such as a shock absorber may be provided, being placed betweenisolation device 50 and borehole monitoring assembly 10. In someembodiments, noise suppression methods, such as slacking the connectingcable between components, may be used to reduce the possibility of noisetransmission. Noise suppression devices or methods similarly may be usedbetween the sensors 160 in an array. In some embodiments of theinvention, noise suppression may be performed by digitally processingthe signals generated by the measurements made by the acoustic energysensors.

Borehole assembly 100 may also include apparatuses or features for usein the hydraulic fracturing process. In the event that conveyance 30 iscoiled tubing, one such apparatus may be a jetting nozzle 86 that isplaced above the isolation device 50 to permit fluids to be pumped downthe string 30 and out the jetting nozzle 86 to clean out debris such assand that may accumulate above the packer 30. The jetting nozzle 86 mayalso be used for purposes of perforating the casing string 22 andforming the perforation tunnels 61 in lieu of a perforating gun. In thisregard, an abrasive fluid may be communicated downhole through thecentral passageway of the string 30, and the abrasive fluid is radiallydirected by the jetting nozzles 86 toward the casing string 22 so thatthe resultant jets perforate the casing string 22 and form tunnels intothe surrounding formation.

The borehole assembly 100 may include a feature such as a clean-outport, which may be selectively opened or closed above located aboveisolation device 50 to permit, if desired, fluid pumped down the annulusto reverse flow the fluid up coiled tubing. Methods such as ball dropsor mechanical actuation may be used to selectively open or close aclean-out port.

In some embodiments, borehole assembly 100 may include one or moreadditional isolation devices located above borehole monitoring assembly10. Additional isolation devices may be single or multi-set.

The borehole assembly 100 may include one or more additional devices toprovide wellbore information. For example, the borehole assembly 100 mayfurther include a pressure or temperature sensor or both. In someembodiments of the invention, a gyroscope may be provided for use inorientating the sensors 160 or for determining the orientation of theborehole monitoring assembly 10 to permit subsequent data adjustment.Alternatively the sensors may be orientated by methods such as a threecomponent hodogram analysis that uses the recording of a calibrationshot in a nearby well or at the surface. By recording and analyzing oneor more such shots the tool orientation may by calculated by the knownmethods such as using plane geometry and the assumption of a straightray from source to receiver, projecting the ray onto a perpendicularplane and rotating the projection through the horizontal polarizationangle to give the direction of the x-component sensor and the relativebearing angle or the method of calculating the relative bearing anglefrom the 3C polarization of the direct P-wave arrival as described inBecquey, M. and Dubesset, M., 1990, Three-component sonde orientation ina deviated well (short note): Geophysics, Society of Exploration.Geophyics, 55, 1386-1388.

In accordance with some embodiments of the invention, the boreholeassembly 100 may include other devices, which are directed to otherfunctions. For example, in accordance with some embodiments of theinvention, the borehole assembly 100 may include a casing collar locator(CCL) 87 that is used for purposes of precisely locating the boreholeassembly 100 downhole or other tool. In this regard, the CCL 87 may be amagnetically-sensitive device that generates a signal (observed at thesurface of the well 8) for purposes of detecting casing joints of thecasing 22 for purposes of precisely locating the assembly 100. This maybe helpful for purposes of precisely locating the jetting nozzles 86when the jetting nozzles 86 perforate the casing 22 and the formation ofinterest 60. As another example of another potential device of theborehole assembly 100, in accordance with some embodiments of theinvention, the assembly 100 may include a tension sub 85, which islocated below the isolation device 50 and is used to monitor the tensionof the cable, which extends to the sondes 120. In this regard, shouldthe cable or sondes 120 become lodged in the well 8, the correspondingtension indicative of this event is sensed by the tension sub 85 andcommunicated to the surface of the well. Therefore, corrective measuresmay then be undertaken for purposes of safely dislodging the sondes 120.

As another example, the borehole assembly may include a supplementalsensor, for example a pressure or temperature sensor, capable ofproviding a downhole measurement. In this regard, the measurementobtained using the supplemental sensor may be used in conjunction withor separately from the measurements obtained using sensors 160 tomonitor hydraulic fracturing. In some embodiments, the supplementalsensor may be an additional acoustic sensor, such as a hydrophone,useful for measuring noise in the form of borehole acoustic waves. Thesupplemental sensor may be an accelerometer. In some embodiments, aplurality of supplemental sensors, specifically acoustic sensors, may beprovided. Output from this supplemental sensor may be used to digitallysuppress or remove noise by processing the measurements from theacoustic sensor(s). This use is different from the use of measurementsfrom acoustic sensors in an array to eliminate noise by cumulativeprocessing of the measurements such as known for vertical seismicprofiles.

The borehole assembly 100 may also include, in accordance withembodiments of the invention, a remotely-actuated latch, or connector90, for purposes of selectively connecting the borehole assembly 100 toand releasing the assembly 100 from the string 30 (thereby leaving theassembly 100 downhole) when multiple zones are treated, as furtherdescribed below. Thus, many variations are possible and are within thescope of the appended claims.

The hydraulic fracturing and monitoring may proceed as follows inaccordance with some embodiments of the invention. The wellbore 20 isfirst completed with the casing 22, and then, the casing 22 isperforated at one or more subterranean formations of interest 60. Inaccordance with embodiments of the invention, the borehole monitoringassembly 10 may then be conveyed into the wellbore 20 on the string 30.The isolation device 50 is simultaneously conveyed in wellbore 20 on thestring 30 at a desired position above assembly 10. The isolation device50 is set in place to provide a seal in the annulus between the string30 and the casing 22, thereby isolating borehole monitoring assembly 10in wellbore 20 below isolation device 50. If additional isolationdevices are provided, they may be actuated or set in place to providefurther isolation between the borehole monitoring assembly 10 and theisolation device 50.

Hydraulic fracturing fluid or injection fluid is then pumped at pressuredown the annulus formed between conveyance 30 and casing 22 or wellborewall and into the subterranean formation of interest 60. The hydraulicfracturing fluid may be any fluid useful for fracturing a subterraneanformation, including but not limited to wellbore treatment fluids,hydrocarbons, water, produced water, disposal water, foamed fluids orgases, such as natural gas or CO₂.

The isolation device 50 and if provided, additional isolation device ordevices, separate borehole monitoring assembly 10 from hydraulicfracturing fluids and operations performed in the wellbore aboveisolation device 50. Isolation device 50 may be any packer, inflatableor mechanical device capable of being set and released that providessufficient sealing pressure within the wellbore to isolate the boreholemonitoring assembly from the pressured hydraulic fracturing or injectionfluid. In embodiments of the invention where the borehole monitoringassembly 10 is deployed in the wellbore below the isolation device 50,the isolation device 50 includes feed-throughs to permit communicationline 40 to pass through the isolation device 50 and to boreholemonitoring assembly 10. Some embodiments may include stiff bridles ordeployment bars for use in deploying borehole sensor assembly 10 indeviated, horizontal or pressurized wells.

In accordance with embodiments of the invention described herein,referring to FIG. 3, a technique 200 may be used to monitor thehydraulic fracturing of a particular formation of interest. Pursuant tothe technique 200, the borehole assembly 100 is run into the well intoposition, pursuant to block 204, the borehole assembly comprising anacoustic sensor. A hydraulic fracturing operation is then performed bypumping fracturing fluid into the wellbore at pressure, pursuant toblock 206. The one or more acoustic sensors are used to monitor acousticenergy pursuant to block 208. The acoustic energy monitored may be fromfracturing operations, or may result from fracturing operations in whichthe hydraulic fracturing fluid comprises an acoustic signal generatingelement, such as a noisy proppant described in U.S. Pat. No. 7,134,492,incorporated herein in its entirety by reference. Sensor 160 is used tomonitor the operation or the signals generated by the acoustic signalgenerating element.

Although the hydraulic fracturing and monitoring of a single formationof interest, or zone, is described herein for purposes of clarifyingcertain aspects of the invention, it is noted that other embodiments arepossible and are within the scope of the appended claims. Morespecifically, in accordance with some embodiments of the invention, theborehole assembly 100 may be used in conjunction with the hydraulicfracturing and monitoring of several zones in the well.

In this manner, referring to FIG. 4, in accordance with some embodimentsof the invention, a technique 250 includes running (block 254) aperforating device downhole in a well to a particular depth. Theperforating device is then used to perforate the casing or wellbore(block 258). The borehole assembly 100 is positioned in the well,pursuant to block 262. Next, the isolation device 50 is set (block 266)and a fracturing operation is subsequently performed and the sensors 160are used to monitor the operation, pursuant to block 270. In someembodiments, a fracturing model may be established and updated using ameasurement from sensor 160.

After the completion of the hydraulic fracturing operation, adetermination is made (diamond 274) whether another zone is to befractured. If not, then the borehole assembly 100 is pulled out of thewell, pursuant to block 278. If another zone is to be fractured, thenthe next zone is perforated, pursuant to block 254; and pursuant toblocks 258, 262, 266 and 270, another zone is hydraulically fracturedand monitored.

Thus, pursuant to the technique 250, zones may be fractured andmonitored in the well as set forth in FIG. 4. It is noted that thetechnique 250 is provided for purposes of an example, as othertechniques may be used for purposes of hydraulic fracturing andmonitoring, in accordance with other embodiments of the invention.

Referring to FIG. 5, in accordance with some embodiments of theinvention, a technique 300 includes running (block 304) a perforatingdevice downhole in a well to a particular depth. The perforating deviceis then used to perforate the casing or wellbore (block 308). Theborehole assembly 100 is positioned in the well, pursuant to block 312.In some embodiments, borehole assembly 100 may comprise the perforatingdevice. A fracturing operation is subsequently performed and the sensors160 are used to monitor the operation, pursuant to block 320.

After the completion of the hydraulic fracturing operation, adetermination is made (diamond 324) whether another zone is to befractured. If not, then the borehole assembly 100 is pulled out of thewell, pursuant to block 328. If another zone is to be fractured, thenthe perforated next zone is perforated, pursuant to block 324; andpursuant to blocks 304, 308, 312, and 320, another zone is hydraulicallyfractured and monitored.

Thus, pursuant to the technique 300, zones may be fractured andmonitored in the well as set forth in FIG. 5. It is noted that thetechnique 300 is provided for purposes of an example, as othertechniques may be used for purposes of hydraulic fracturing andmonitoring, in accordance with other embodiments of the invention.

The borehole monitoring assembly 100 and techniques that are describedherein may offer one or more advantages and/or improvements overconventional hydraulic monitoring techniques and devices. In particular,placement of the borehole monitoring assembly in the injection wellrather than a separate monitoring well reduces the time and expenserequired for drilling a separate well. Placing the acoustical sensorsbelow the packer isolates the sensors from the fracturing fluid andreduces the risk of damage to the sensors from the fracturing fluid asit is pumped down the wellbore. Similarly, placing communication line 40within the string 30 isolates it from the fracturing fluid pumped downthe annulus and significantly reduces the possibility of erosion ordamage to the communication line. Furthermore, the placement of sensors160 below the isolation device 50 has the effect of providing isolationfrom flow-induced noise.

Prior to the present invention, noise generated by pumping fracturingfluid in a wellbore has inhibited the ability to make successfulmicroseismic measurements in the injection well. Several elements areused individually or in combination in the present invention to isolateand attenuate wellbore noise. Placing the acoustic energy sensor orsensors below the isolation device 50 provides a barrier to direct flownoise. Isolation device 50 is designed to efficiently allowsetting/unsetting, cleaning of sand deposited on top, and enablement ofnoise isolation techniques (e.g., slacking). Configuring sensors 160 inan acoustic energy sensor package and mechanically isolating the sensorpackage 140 (see FIG. 2) from the tool body 124 may be used to attenuatenoise (known as tubewaves) propagating in the wellbore fluid. Slackingcommunication line 40 may be used to attenuate noise propagating alongthe communication line 40 or borehole monitoring assembly 10. Isolationdevice 50 may comprise a compressional setting that is operational on adownward movement that accommodates slacking of communication line 40.

Shock absorbers designed to attenuate noise propagating in thebottom-hole-assembly may be inserted between isolation device 50 and theacoustic sensors. Digital filtering may be used to identify upward anddownward propagating noise with distinctly different characteristicsfrom the microseisms. Such digital filtering techniques such as adaptivebeamforming or velocity filtering may be used to attenuate noise. Asub-array of hydrophones placed within an array of geophones oraccelerometers may be useful for identifying and removing propagatingfluid (tube) waves. Additionally, pumping noise is at low frequencies(<20 Hz) much below the typical microseismic band and may besubstantially removed by conventional high-pass filters.

The borehole assembly 100 may further include other measurement devicessuch as pressure, temperature, gyroscopes, or any other device usefulfor measuring indications of fracture characteristics. The boreholeassembly 100 may also include fracturing tools positioned above theisolation device 50 for use in the hydraulic fracturing process, such asjetting nozzle, clean-up port, etc. Furthermore, the borehole assembly100 may include a single or multi-set isolation devise above themeasurement devises to protect it from the impact of the fracturetreatment.

Although directional and terms of orientation, such as “vertical,” “up,”“down,” etc. have been used for reasons of convenience in the foregoingdescription, it is understood that such directions and orientations arenot necessary to practice the invention. For example, in accordance withother embodiments of the invention, the borehole assembly 100 may beused in a lateral wellbore. Therefore, many variations are contemplatedand are within the scope of the appended claims.

While the present invention has been described with respect to a limitednumber of embodiments, those skilled in the art, having the benefit ofthis disclosure, will appreciate numerous modifications and variationstherefrom. It is intended that the appended claims cover all suchmodifications and variations as fall within the true spirit and scope ofthis present invention.

1. A method usable with a well, comprising: deploying an assembly into awellbore, the assembly comprising at least one sensor; injecting afracturing fluid under pressure into the wellbore to hydraulicallyfracture a subterranean formation of interest; isolating the sensor fromthe fracturing; and measuring acoustical energy generated by thehydraulic fracturing using said at least one sensor.
 2. The method ofclaim 1, wherein the isolating comprises setting a packer of theassembly.
 3. The method of claim 2, further comprising: positioning saidat least one sensor below the packer.
 4. The method of claim 2, furthercomprising: releasing the packer; repositioning the borehole assembly inthe wellbore; and repeating the injecting and isolating.
 5. The methodof claim 1, wherein the deploying comprises deploying the assembly on astring, the method further comprising disposing a communication lineinside the string to establish communication between said at least onesensor and the surface of the well.
 6. The method of claim 1, whereinsaid at least one sensor comprises a plurality of sensors, the methodfurther comprising: spacing the sensors along the wellbore.
 7. Themethod of claim 1 further comprising: retrieving the assembly from thewellbore.
 8. The method of claim 1, wherein the measuring occursconcurrently with the injecting.
 9. The method of claim 1, furthercomprising: storing data indicative of the acoustical energy measured byby said at least one sensor in a memory of the assembly; and retrievingthe data from the memory after the assembly is retrieved from the well.10. A method for monitoring hydraulic fracturing comprising: a)deploying a borehole assembly into a wellbore on a coiled tubing havinga communication line disposed therein, the borehole assembly comprisingborehole monitoring assembly positioned below a packer, the boreholemonitoring assembly comprising at least one acoustic energy sensor; b)placing the borehole assembly below a subterranean formation ofinterest, c) setting the packer below the subterranean formation ofinterest; d) injecting a fracturing fluid under pressure down theannulus, thereby hydraulically fracturing the subterranean formation ofinterest; and e) using the acoustic energy sensor to make a measurementof acoustical energy generated by the hydraulic fracturing.
 11. Themethod of claim 10, further wherein the communication line is selectedfrom the group consisting of wireline, slickline, fiber optics and afiber optic tether.
 12. The method of claim 10, wherein the boreholemonitoring assembly comprises more than one sensor, the sensors beingspaced along the wellbore, the sensors being separated from thesubterranean formation by the packer.
 13. The method of claim 10,further comprising the steps (f) of releasing the packer and (g) movingthe borehole assembly in the wellbore, wherein steps (b) through (f) arerepeated.
 14. The method of claim 10, wherein the acoustical energymeasurement comprises communicating via the communication line.
 15. Themethod of claim 14, further wherein the step of injecting a fracturingfluid comprises modifying based on the acoustical energy measurement.16. The method of claim 10, further comprising retrieving the boreholeassembly from the wellbore.
 17. The method of claim 10, furthercomprising establishing a fracturing model and updating the fracturingmodel using at least one acoustical energy measurement.
 18. An wellboreapparatus for hydraulic fracture monitoring comprising a boreholeassembly deployed on coiled tubing, the assembly having a tool body witha least one acoustic energy sensor disposed therein, an isolationdevice, and at least one washout port adjacent to the isolation device,the assembly being connected to coiled tubing having a communicationline disposed therein.
 19. The apparatus of claim 18, wherein the atleast one acoustic energy sensor comprises selected from the groupconsisting of geophone, hydrophone, and accelerometer.
 20. The apparatusof claim 18, wherein the isolation device comprises a packer.
 21. Theapparatus of claim 18, further comprising means to process data from theacoustical energy sensor.
 22. An apparatus usable with a well,comprising: a tool body; an isolation device disposed on the tool body;at least one acoustic sensor disposed on the tool body to monitorhydraulic fracturing.
 23. The apparatus of claim 22, wherein said atleast one acoustic sensor comprises at least one of a geophone,hydrophone and accelerometer.
 24. The apparatus of claim 22, furthercomprising: a string to convey the isolation device and said at leastone acoustic sensor downhole as a unit.
 25. The apparatus of claim 22,further comprising: a remotely-activated connector to selectivelyconnect the isolation device to a tubular string.
 26. The apparatus ofclaim 22, wherein the isolation device comprises a packer.
 27. Theapparatus of claim 22, further comprising: a memory connected to anddeployed downhole with the tool body to store data provided by said atleast one sensor such that the data is retrieved from the memory afterthe apparatus is retrieved from the well.
 28. A method for monitoringhydraulic fracturing comprising: a) deploying a borehole assembly into awellbore, the borehole assembly comprising a borehole monitoringassembly having at least one acoustic energy sensor; b) injecting afracturing fluid under pressure, thereby hydraulically fracturing asubterranean formation of interest; and c) using the acoustic energysensor to make a measurement of acoustical energy.
 29. The method ofclaim 28, wherein the borehole assembly further comprises a supplementalsensor.
 30. The method of claim 28, wherein the fracturing fluidcomprises an acoustical energy generating element.
 31. The method ofclaim 28, wherein the fracturing fluid comprises a noisy proppant. 32.The method of claim 28, further comprising the steps (e) of moving theborehole assembly in the wellbore, wherein steps (b) through (c) arerepeated.
 33. The method of claim 29, wherein the supplemental sensor isan acoustic energy sensor.
 34. The method of claim 33, furthercomprising the step of using the output from the supplemental sensor inprocessing the measurement of acoustic energy.
 35. The method of claim28, further comprising the orientating the borehole assembly.